Geothermal power as an alternative to coal

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Geothermal power (from the Greek roots geo, meaning earth, and thermos, meaning heat) is power extracted from heat stored in the earth. Geothermal energy is generated in the Earth's core, where temperatures hotter than the sun's surface are continuously produced by the slow decay of radioactive particles.

Enhanced geothermal systems (EGS) use heat-mining technology to extract and utilize the earth’s stored thermal energy. A 2006 report by MIT and funded by the U.S. Department of Energy on EGS found that U.S. EGS resources far exceeded the country’s energy use in 2005, and that with an R&D investment of $1 billion over 15 years, EGS could be capable of producing electricity for as low as 3.9 cents/kWh.

Geothermal Reservoirs
Naturally occurring large areas of hydrothermal resources are called geothermal reservoirs. Most geothermal reservoirs are deep underground with no visible clues showing above ground. Geothermal energy sometimes finds its way to the surface in the form of volcanoes and fumaroles (holes where volcanic gases are released), hot springs, and geysers. The most active geothermal resources are usually found along major plate boundaries where earthquakes and volcanoes are concentrated. Most of the geothermal activity in the world occurs in an area called the Ring of Fire that encircles the Pacific Ocean.

Geothermal Energy in the U.S.
Most of the geothermal reservoirs in the United States are located in the western States and Hawaii. California generates the most electricity from geothermal energy: "the Geysers" dry steam reservoir in northern California is the largest known dry steam field in the world and has been producing electricity since 1960.

The United States generates more geothermal electricity than any other country, although the amount of electricity it produces is less than 0.5% of all electricity produced in United States. Only five States have geothermal power plants:
 * California has 34 geothermal power plants, which produce almost 90% of U.S. geothermal electricity.
 * Nevada has 15 geothermal power plants.
 * Hawaii, Montana, and Utah each have one geothermal plant.

Geothermal Power Plants
Geothermal power plants work by pumping hot water from deep beneath Earth's surface, which can either be used to turn steam turbines directly or to heat a second, more volatile liquid such as isobutane (which then turns a steam turbine). The geothermal resources should be 300°F to 700°F, and are reached by drilling wells into the Earth, one to two miles deep, and piping the steam or hot water to the surface for the plants to convert to energy.

There are three basic types of geothermal power plants:
 * Dry steam plants use steam piped directly from a geothermal reservoir to turn the generator turbines.
 * Flash steam plants take high-pressure hot water from deep inside the Earth and convert it to steam to drive generator turbines. When the steam cools, it condenses to water and is injected back into the ground to be used again. Most geothermal power plants are flash steam plants.
 * Binary cycle power plants transfer the heat from geothermal hot water to another liquid, allowing cooler geothermal reservoirs to be used than with dry steam and flash steam plants. The heat causes the second liquid to turn to steam, which drives a generator turbine.

Enhanced Geothermal Systems
Traditionally geothermal has been built around natural “wells” that generate steam using the heat of the earth, such as "the Geysers" dry steam reservoir in northern California. This provides for reliable power, but the scale at which such geothermal power is available is limited worldwide. Enhanced geothermal energy creates artificial geothermal wells and would increase the availability of geothermal power.

The development of binary cycle power plants as well as improvements in drilling and extraction technology may enable enhanced geothermal systems over a much greater geographical range.

Enhanced geothermal systems (EGS) operate by:
 * 1) drilling a production-injection well into hot rock (the rock should have limited fluid content and permeability);
 * 2) injecting water into the well at a pressure high enough to cause fracturing, or open up fractures already present in the rock, until fractures extend a significant distance from the initial well;
 * 3) drilling multiple wells around the initial production well, to overlap the fracture system from (2), and then circulating water to capture the heat from the rock and use it to generate power.

MIT Report
A 2006 report by MIT and funded by the U.S. Department of Energy, conducted the most comprehensive analysis to date on the potential and technical status of EGS. The 18-member panel, chaired by Dr. Jefferson Tester of MIT, reached several significant conclusions:


 * 1) Resource Size: The MIT report calculated the United States total EGS resources from 3–10 km of depth to be over 13,000 zettajoules, of which over 200 ZJ would be extractable, with the potential to increase this to over 2,000 ZJ with technology improvements — sufficient to provide all the world's current energy needs for several millennia. The report found that total geothermal resources, including hydrothermal and geo-pressured resources, to equal 14,000 ZJ — or roughly 140,000 times the total U.S. annual primary energy use in 2005.
 * 2) Development Potential: With a modest R&D investment of $1 billion over 15 years (or the cost of one coal power plant), the report estimated that 100 GWe (gigawatts of electricity) or more could be installed by 2050 in the United States. The report further found that the "recoverable" resource (that accessible with today's technology) to be between 1.2–12.2 TW for the conservative and moderate recovery scenarios respectively.
 * 3) Cost: The report found that EGS could be capable of producing electricity for as low as 3.9 cents/kWh. EGS costs were found to be sensitive to four main factors: 1) Temperature of the resource, 2) Fluid flow through the system measured in liters/second, 3) Drilling Costs, and 4) Power conversion efficiency.

United States
The United States pioneered the first EGS effort--then termed Hot Dry Rock--at Fenton Hill, New Mexico with a project run by the federal Los Alamos Laboratory. It was the first attempt anywhere to make a deep, full-scale HDR reservoir, and efforts there spanned 1974 through 1992, in two phases. Ultimately, the project was unable to generate net energy, and the project was terminated.

EGS funding languished for the next few years, and by the next decade, U.S. efforts focused on the less ambitious goal of using EGS to improve the productivity of existing hydrothermal resources. According to the Fiscal Year 2004 Budget Request to Congress from DOE's Office of Energy Efficiency and Renewable Energy:

"EGS are engineered reservoirs that have been created to extract heat from economically unproductive geothermal resources. EGS technology includes those methods and equipment that enhance the removal of energy from a resource by increasing the productivity of the reservoir. Better productivity may result from improving the reservoir’s natural permeability and/or providing additional fluids to transport heat."

In Fiscal Year 2002, this vision translated into completing "preliminary designs for five competitively selected projects employing EGS technology," and the selection of one project for "full-scale development" at the Coso Hot Springs geothermal field at the U.S. Naval Weapons Air Station in China Lake, California, and two additional projects for "preliminary analysis from a new solicitation" at Desert Peak in Nevada and Glass Mountain in California. Funding for this effort totaled $1.5 million.

In Fiscal Year 2003, $3.5 million was appropriated to launch the Coso project, with the aim of improving the permeability of an existing poorly performing well, and to complete the conceptual design and feasibility studies at the Desert Peak and Glass Mountain sites.

The Fiscal Year 2004 request for $6 million was to "[s]tep up work on EGS cost-shared projects' at the three sites, to include "drilling and reservoir stimulation experiments" at one and drilling a production well at another.

The U.S. Department of Energy USDOE issued two Funding Opportunity Announcements (FOAs) on March 4 2009 for EGS. Together, the two FOAs offer up to $84 million over six years, including $20 million in fiscal year 2009 funding, although future funding is subject to congressional appropriations.

The DOE followed up with another FOA on March 27, 2009, of stimulus funding from the American Reinvestment and Recovery Act for $350 million, including $80 million aimed specifically at EGS projects.

California AltaRock Project
In December 2009 a California EGS project was called off by the operating company, AltaRock Energy. The project, at a site about 100 miles north of San Francisco called the Geysers, was partly funded by the Department of Energy and was the Obama administration’s first major test of geothermal energy as a significant alternative to fossil fuels. It is not known why AltaRock pulled out. The project’s collapse came a day after Swiss government officials permanently shut down a similar project in Basel due to induced seismicity.

Seismicity Problems with Enhanced Geothermal
Some seismicity is inevitable and, indeed, expected in EGS, which involves pumping fluids at pressure to enhance or create permeability through the use of hydraulic fracturing techniques. Depending on the rock properties, and on injection pressures and fluid volume, the reservoir rock may respond with tensile failure, as is common in the oil and gas industry, or with shear failure of the rock's existing joint set, as is thought to be the main mechanism of reservoir growth in EGS efforts.

Experience in the field has shown that seismicity associated with hydraulic stimulation can be mitigated and controlled through predictive siting and other techniques. According to the 2006 MIT report: "With current technology, it appears feasible that the number and magnitude of these induced events can be managed. In fact, based on substantial evidence collected so far, the probability of a damaging seismic event is low, and the issue – though real – is often one more of public perception."

Basel Earthquakes
Induced seismicity at an EGS project in Basel, Switzerland, led the city (which was a partner) to suspend the project and conduct a seismic hazard evaluation, resulting in the cancellation of the project in December 2009.

Although the Basel project had established an operational approach before proceeding with the geothermal stimulation for addressing induced earthquakes of concern, it had not performed a thorough seismic risk assessment beforehand, even though most of the city was destroyed in 1356 by a magnitude 6.5 earthquake. Basel is in a known earthquake zone and sits atop a historically active fault.

On 8 December 2006, only 6 days after the main stimulation started on 2 December, the HDR project in Basel was suspended when an earthquake tripped a 4-level "traffic light" scheme established for halting operations in the event of unacceptable induced earthquake occurrences. Trip points of Richter Magnitude ML 2.9 and a peak ground velocity of 5 millimeters per second were established by the project as independent criteria for a "red alert" that entailed halting fluid injection and bleeding-off to minimum wellhead pressure. Lesser operational curtailments were triggered for lower magnitude and peak ground velocity thresholds.

Earlier that day, a "yellow alert"--the second level--was called at 03:06 local time after a 2.6 ML event with peak ground velocity of 0.55 mm/s, which exceeded the "soft" 2.3 ML and 0.5 mm/s thresholds. As a precaution, the injection rate was reduced at 04:04.

Following further events that were larger than 2.0 ML, a level-three "orange alert" was declared—the injection was stopped at 11:34 and the well shut-in, maintaining the pressure. However, a 2.7 ML event occurred at 15:46, followed by a 3.4 ML event at 16:48, and so in accordance with the response strategy, the well was bled off as soon as practicable.

The largest event prompted concern from local residents. Further tremors exceeding magnitude 3 were recorded on 6 January (measuring 3.1), 16 January 2007 (3.2), and 2 February 2007 (3.2).

The six borehole seismometers installed near the Basel injection well to monitor the natural background seismicity and the geothermal stimulation recorded more than 13,500 potential events connected with the geothermal project, from which 3,124 were of sufficient quality to permit [hypocenter] determinations in the period 2-12 December 2006, which spanned the main stimulation and the decline in the event rate. During the post-stimulation period from 13 December 2006 onward, a further 350 locatable events were detected up to 2 May 2007, by which time events were occurring sporadically at around one per day. In all, locations for more than 3,500 events were determined.

Of these more than 3,500 events, only the 200 largest (magnitudes between 0.7 and 3.4) were also observed by the earthquake networks of the Swiss Seismological Service and the Seismological Service of Baden-Wuerttemberg,[33] The remainder were too small to be observed or felt at the surface. For the period through 24 January 2007, there were 168 earthquakes with magnitudes> 0.6, 15 with ML >2, and three with ML > 3. All of these were within 1 km of the wellbore, and at depths between 4 and 5 km, near the well bottom. There were only 9 events with an ML of 2.5 or larger in the borehole vicinity for the period through 2007. Five occurred in December 2006, two in January 2007, and one each February and March.

The project was led by Geopower Basel, which had paid around 9 million Swiss francs (U.S. $9 million) in compensation for cracked walls and similar damage on nearby houses and other buildings from the tremors. Head of Basel's environmental and economic department Christoph Brutschin said a risk assessment showed the possibility of further earthquakes would be too high to continue drilling up to 5,000 meters (16,400 feet) into the ground — the depth necessary to heat the water from the rocks. Switzerland is looking in other areas less to tap the heat of the Earth's crust in zones that are less earthquake-prone.

Costs
Various reports suggest that geothermal would be cheaper than coal plants. A 2009 report by the international investment bank Credit Suisse concluded that geothermal may be cheaper than every other source, including coal. In making their calculations, the report factored in President Barack Obama’s stimulus plan, including $28 billion in direct subsidies for renewable energy and another $13 billion for research and development. The report concludes geothermal power costs 3.6 cents per kilowatt-hour, versus 5.5 cents per kilowatt-hour for coal.

However, Scientific American stressed some potential problems with this figure:


 * First, there are the tax incentives, which save about 1.9 cents per kilowatt-hour and are right now only guaranteed through 2013.
 * Second, the figure assumes that the money to build a new geothermal plant is available at reasonable interest rates of 8 percent, which might be overly-optimistic in today's economic climate, adding to the high up-front costs.
 * Third, the geothermal industry has the same exploration challenges as the oil and gas industry, since you cannot see geothermal resources from the surface. The Credit Suisse analysis doesn't factor in exploration costs, which can run hundreds of thousands of dollars for per well.

Despite these caveats, the Credit Suisse analysis is backed up by earlier studies, such as a 2006 Western Governor's Association (WGA) report on geothermal resources in the U.S. Southwest. Using a similar economic model, but assuming a higher interest rate than the Credit Suisse analysis, the WGA found that geothermal could be produced from existing resources and existing technology for about 6.5 cents per kilowatt-hour, once a federal 1.9 cent per kilowatt-hour tax credit is included.

A 2009 report from the NYU Stern School of Business found that with a total investment of about $3.3 billion, geothermal sources could be as cheap as coal in a couple of years.

Emission Levels
Geothermal power plants do not burn fuel to generate electricity, so their emission levels are relatively low, releasing less than 1% of the carbon dioxide emissions of a coal-fired plant. Geothermal plants use scrubber systems to clean the air of the hydrogen sulfide naturally found in the steam and hot water. According to the Energy Information Administration, geothermal plants emit 97% less acid rain-causing sulfur compounds than are emitted by fossil fuel plants.

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